Refinery desalter improvement

ABSTRACT

The invention relates to improved methods of desalting hydrocarbon feeds using a separator with a stacked disk centrifuge to separate an emulsified oil and water rag layer. This method is effective for desalting heavy, high ionic, and non-traditional crude oils.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefitunder 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/368,103filed Jul. 27, 2010, entitled “REFINERY DESALTER IMPROVEMENT,” which isincorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH

None.

FIELD OF THE INVENTION

This invention relates to improved methods of desalting hydrocarbonfeeds using a stacked disk centrifuge to separate an emulsified oil andwater rag layer. This method is effective for desalting heavy, highionic, and non-traditional crude oil sources.

BACKGROUND OF THE INVENTION

Desalting crude oils is a two step process—creating a fine dispersion oremulsion of fresh water and the oil, and then effecting a phaseseparation of the water from the oil. Smaller water droplets providemore area for mass transfer of ionic contaminants (mostly chloridesalts) from the oil into the water than large droplets. In a typicalrefinery desalter, the dispersion is created by adding water to the rawcrude and then passing the mixture through shell and tube heatexchangers and a mix valve. The mix valve typically imposes less than 10psi (some plants run at up to about 15-18 psi) of pressure drop on themixture to created a dispersion. The dispersion is then broken and phaseseparated in a liquid-full large vessel at about 300° F., with residencetimes of 30 to 40 minutes, and water coalescence is enhanced by chemicaldemulsifier addition and the imposition of electrostatic fields.

In U.S. Pat. No. 4,415,434, Hargreaves and Hensley describe a multistageprocess for dedusting and desalting tarsands, shale oils and coals thatuses a standard centrifuge to remove dust and solids from an oil-wateremulsion. Thacker and Miller describe a similar process in U.S. Pat. No.4,473,461 for dedusting heavy oil derived from solidhydrocarbon-containing material such as oil shale, coal or tar sand,into purified streams of oil. Goyal, et al., U.S. Pat. No. 5,219,471,use an electrostatic process of blending crude oil with water anddesalting chemicals to remove metals and insoluble materials from thecrude oil. In Ohsol, et al., U.S. Pat. No. 4,938,876, U.S. Pat. No.5,882,506 and U.S. Pat. No. 5,948,242, the rag-oil layer, wash water,and fines are mixed to create a single stream from which oil isrecovered with a lighter hydrocarbon diluent by demulsification andphase separation. Engel, et al., U.S. Pat. No. 7,612,117, use of a classof acetylenic surfactants to break water and oil emulsions. Theseprocesses dissolve, “break” or disrupt emulsions prior to use ofcentrifugal forces to create separate oil and water phases.

Oil/water separators like air flotation units, dissolved air flotation,the Ohsol separation process, and other separation technologies are wellestablished in the crude oil refining industry. Unfortunately, theindustry is averse to changes in technology and new technologies must bewell established and proven before implementation. Even with a need forbetter separation (Nnanna, 2008), developing new technologies isdifficult, expensive and very hard to implement and test, especially ona scale comparable to the hundred thousand or more barrels-per-dayrequired for even small refineries.

Standard desalters have worked well historically with the lighter, lessviscous crude oils or for separation of solids from crude and shale oilsources, but their performance is challenged by less traditionallow-gravity, high viscosity crude oil. Traditional crude oil desaltershave poor ionic salt removal as refineries process lower gravity/higherviscosity oils. When working with unconventional oils, pilot scaledesalting runs using electrostatic desalters, including electrostaticcoalescence technology or electrocoagulation techniques and the Ohsolprocess for heavy oils were not effective. Because these unconventionalcrudes generate higher water-in-crude and higher oil-in-water levelsthan traditional crude oils, improved methods are required to dewaterand desalt unconventional and difficult to work with crude oils. What isrequired is an inexpensive method that can be integrated into currentrefinery processes for separating crude oil from the desalter rag layer.

BRIEF SUMMARY OF THE DISCLOSURE

The current invention provides a process for separating crude oil from arefinery desalter rag layer by removing a rag layer stream from thedesalter, feeding the rag layer stream to a disk stack centrifuge,separating water from crude oil, adding separated crude oil to the crudeoil feed stream, and returning separated water to the desalter toimprove crude oil separation and desalting. Using the disk stackcentrifuge to separate the desalter rag layer into brine and desaltedcrude oil is an inexpensive way to increase the capacity of conventionaldesalters, allow refineries to process heavier oils, and improvedesalter performance. The rag layer is quickly separated withoutrequiring additional equipment, chemicals, or re-engineering of therefinery process.

In one embodiment, an improved process for separating non-traditionalcrude oil feedstock is described where:

-   -   A) a desalter separator tank is provided that generates three        streams, an outgoing oil feedstream, an outgoing aqueous        feedstream and an outgoing emulsion or “rag layer” feedstream,    -   B) the rag layer from the separator tank is removed at a rate        that maintains an approximate rag layer height in the separator        tank,    -   C) the rag layer is fed to one or more disk stack centrifuges,        to generate a cleaned oil stream and an aqueous stream,    -   D) the separated aqueous phase is returned to the desalter        vessel, and    -   E) the cleaned oil is discharged to the desalter oil outlet        stream.

In another embodiment, a crude oil desalter system is described with anoil and water feedstream comprising a crude oil and water mixture, aseparator connected to said feedstream wherein said separator comprisesthree or more outgoing streams including an outgoing crude oil stream,an outgoing wastewater stream and an outgoing rag layer stream, one ormore outgoing rag layer streams connected to a disk stack centrifugewherein said disk stack centrifuge comprises three or more outgoingstreams including an outgoing crude oil stream, an outgoing wastewaterstream and an outgoing solids rich stream, one or more outgoing streamscomprising a desalted crude oil, and one or more outgoing streamscomprising wastewater.

In one embodiment, a process for removing water from crude oil isdemonstrated where an oil and water feedstream is provided with a crudeoil and water mixture, the oil and water feedstream is fed to aseparator with three or more outgoing streams including an outgoingcrude oil stream, an outgoing wastewater stream and an outgoing raglayer stream, the outgoing rag layer stream is removed from theseparator, the rag layer is centrifuged in a disk stack centrifuge thedisk stack centrifuge has three or more outgoing streams including anoutgoing crude oil stream, an outgoing wastewater stream and an outgoingsolids rich stream, a desalted crude oil stream and a wastewater streamare removed from the stack disk centrifuge.

In yet another embodiment, a crude oil emulsion rag layer is reduced byfeeding an oil and water feedstream to a separator with three or moreoutgoing streams including an outgoing crude oil stream, an outgoingwastewater stream and an outgoing rag layer stream, removing theoutgoing rag layer stream from said separator, centrifuging the raglayer in a disk stack centrifuge that has three or more outgoing streamsincluding an outgoing crude oil stream, an outgoing wastewater streamand an outgoing solids rich stream; removing a desalted crude oil streamfrom the separator and the disk stack centrifuge; and removing awastewater stream from the separator and the disk stack centrifuge.

Although emulsion breakers and other chemical additives may be added,this method does not require the addition of these or other chemicalsprior to centrifugation. The temperature of the crude charge is veryimportant to the efficient operation of the desalter. It is notnecessary to rigidly control the temperature at the desalter; however,abrupt changes should be avoided. Dependent upon separator temperatureand centrifuge temperature requirements, the crude charge temperaturemay be modified in a heat exchange, chiller or other methods. In oneembodiment the temperature range is approximately 200° F. to 280° F. Inanother embodiment the crude charge is less than 300° F. Often changingthe feedstream temperature is not required. The approximate rag layerheight maintained in the separator tank can be a percentage of the totalheight, a specific distance from the outgoing oil and water streams, ormay be determined by the crude oil and wastewater/brine contaminants. Inone embodiment rag layer removal rate is increased until the outgoingseparator oil and wastewater are clean enough for further processing. Insome embodiments the rag layer stream is chilled to below 250° C., 225°C., 200° C., or lower prior to centrifugation. The stacked diskcentrifuge can be any stacked disk separator including nozzleseparators, self-cleaning disk separators, solid-wall separators, andthe like which contain a stack of conical disks either with or withoutchambers, surface channels, and the like to separate or collect avariety of materials separated using centrifugal forces. In oneembodiment a nozzle bowl design disk stack centrifuge is used allowingvariable rates of solids removal during the oil and water centrifugationprocess.

The crude oil emulsion can be kept at refining temperatures ranging fromambient temperature up to 300° F. dependent upon the pressure,contaminants, and source of the feed stream. The crude oil emulsion mayby fed through an optional heat exchanger to achieve a desiredtemperature between approximately 200 and 300° F., or about 200° F.,210° F., 220° F., 230° F., 240° F., 250° F., 260° F., 270° F., 280° F.,290° F., up to about 300° F. Because the temperature need not be rigidlymaintained, the temperature may fluctuate by 5° F., 10° F., or more.Rapid changes in temperature should be avoided.

Non-conventional crude oils can be any high salt or heavy crude oilincluding Athabasca oil sands (crude bitumen), Orinoco oil sands (extraheavy oil), Canadian Extra Heavy Oil (CXHO), Western Canadian Select(WCS), MacKay River Heavy (MRH), oil shales, crude bitumens, extra heavyoils, oilsands, tarsands, sour crudes, and mixtures thereof. Heavycrudes include crude oils with a gravity between 10 and 25° API or 900to 1000 kg/m³. Bitumens, tarsands, extra heavy crudes, and the like maybe upgraded prior to being separated.

Water can be any available water source including tap water, de-ionized(DI) water, recycled water, distilled water, chilled water, heatedwater, ultra-purified water, salt water, mixtures thereof, or otherknown water sources. In one embodiment, heated water is added to thecrude oil to increase the temperature of the emulsion layer prior tocentrifuge separation.

The water drop size distributions in the rag layer is approximately 1 to30 μm, approximately 5 to 25 μm, approximately 10 to 15 μm,approximately 9 to 14 μm, approximately 7 μm, 8 μm, 9 μm, 10 μm, 11 μm,12 μm, 13 μm, 14 μm, 15 μm, 17.5 μm, 20 μm, 22.5 μm, 25 μm, 27.5 μm, orapproximately 30 μm. Although water drop size distribution can bereported as an approximate μm, it is a distribution about that size withlarger and smaller diameter drop sizes present in the sample.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefitsthereof may be acquired by referring to the follow description taken inconjunction with the accompanying drawings in which:

FIG. 1: MRH Salt Content and Particle Size Distribution.

FIG. 2: WCS Desalting: Batch T2—The numbered triangles on this plot (andthe others to follow) indicate the times when feed, dehydrated product,and separated water samples were taken around the centrifuge. Thesenumbers correspond to the “WCSR Sample #” in the tables below. After thebatch was complete, the oil samples were analyzed for watercut byHotSpin and for water DSD using the Malvern Mastersizer.

FIG. 3: WCS Desalting: Batch 1.

FIG. 4: WCS Desalting: Batch 2.

FIG. 5: WCS Desalting: Batch 3.

FIG. 6: WCS Desalting: Batch 4.

FIG. 7: WCS Desalting: Batch 5—Dehydration performed with conditionsbelow.

FIG. 8: Chloride Removal: WCS Desalting—Spot samples of chloride removalfor data versus water

FIG. 9: Chloride Removal: WCS Desalting—chloride removal results fromthe three “lots” of desalted crude (batches T2 and 1, batches 2 and 3,and batches 4 and 5) do show correlation between removal and watercut.

FIG. 11: WCS Blended (no added water)—Malvern output for a sample of WCSafter blending in a blend tank. Water by distillation (run by A/S) onanother aliquot of this material showed 0.00 vol %.

FIG. 12: Typical Feed Emulsion (15 vol % watercut)—analysis of a typicalemulsion (Batch 5, 39801-18-1) is shown.

FIG. 13: Typical Feed Emulsion (15 vol % watercut) Small Diameter ModeCut—smaller diameter mode is removed and the data renormalized to 100vol %, the following plot is obtained.

FIG. 14: Typical Dehydrated Product—Malvern results for a dehydratedproduct (39801-18-18). This sample was the last one taken (Sample #24)and the water content was determined to be 1.70 vol % by HotSpin. Itlooks very similar to the plot for the blended crude.

FIG. 15: Solids from Bowl Dispersed in Toluene.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement orarrangements of the present invention, it should be understood that theinventive features and concepts may be manifested in other arrangementsand that the scope of the invention is not limited to the embodimentsdescribed or illustrated. The scope of the invention is intended only tobe limited by the scope of the claims that follow.

When oil and water contact one another for long periods of time, asoccurs during the desalting process, an emulsion layer may form betweenthe two liquids. This emulsion layer in the separator vessel may vary inthickness from several inches to several feet. The thickness andcomposition of the interfacial layer depends on several factors suchas 1) naturally occurring emulsifying agents in the crude, 2) waxyconstituents of the crude, 3) suspended solids in the crude or processwater, 4) the degree of emulsification of the water in the crude, and 5)the processing rate. The emulsion layer may increase to an objectionablethickness in the separator and cause excessive electrical loading,erratic voltage readings, carryover of water and undercarry of oil outof the separator. It is desirable to maintain a constant amount ofemulsion in the separator in order to reduce the amount of emulsion andcontamination of the outgoing streams. Traditional remedies includedadding emulsion breakers, reducing processing rates, and increasing thesize of the separator tank. These limited responses are inadequate withthe more complicated crude oils being processed today and if higherrates of processing are to be maintained. By controlling rag layerthickness and processing the rag layer through a stacked diskcentrifuge, emulsion breaker use is minimized and the footprint of thedesalter does not need to dramatically increase. The improved desalterwith a separator vessel and stacked disk centrifuge can process thecrude oil and brine or water emulsion at a much higher rate and achievebetter separation.

Crude oil is generally classified by the geographic location it isproduced in (e.g. West Texas Intermediate, Brent, or Oman), by its APIgravity, and by its sulfur content. Crude oil may be considered light ifit has low density or heavy if it has high density; and it may bereferred to as sweet if it contains relatively little sulfur or sour ifit contains substantial amounts of sulfur. Oil blends containing bitumenfrom Athabasca oil sands, Western Canadian Select (WCS), MacKay RiverHeavy (MRH)), oil from the Orinoco belt in Venezuela (extra heavy oil),Canadian Extra Heavy Oil (CXHO), and the like are considered heavy oils.Unconventional crude oils include shale oils, crude bitumens, extraheavy oils, oilsands, tarsands, sour crudes, and other crudes with a lowAPI, high sulfur content, high water content, high salt content orcombinations. Often, unconventional crude oils are treated to reducecontaminants and/or mixed with diluents, water and other chemicalsbefore transportation to meet certain specifications including API andreduced corrosion requirements.

“Water” and/or “Wash Water” as used herein may be de-ionized (DI) water,recycled refinery water, distilled water, chilled water, heated water,ultra-purified water, tap water, clarified water, recirculatedwastewater, purified wastewater, or other water source, and combinationsof water sources. Salts in water are measured in parts per thousand byweight (ppt) and range from fresh water (<0.5 ppt), brackish water(0.5-30 ppt), saline water (30-50 ppt) to brine (over 50 ppt). In oneembodiment, DI water is used to allow salt from the crude oil to diffuseinto the aqueous solution, but de-ionized water is not strictly requiredto desalt a crude oil feedstock. In another embodiment, DI water ismixed with recirculated water from the desalter to achieve a specificionic content in either the water before emulsification or to achieve aspecific ionic strength in the final emulsified product. The water usedto scrub the salt, solids, and other impurities from the crude oil maybe injected ahead of the preheat exchanger train and/or immediatelyahead of a mix valve. Wash water rates may be between approximately 5%and approximately 7% by volume of the total crude charge, but may bemuch higher or lower dependent upon the crude oil source and quality.Additional wash water sources include sour water stripper bottoms,overhead condensate, boiler feed water, or clarified river water.Frequently, a variety of water sources are mixed as determined by costrequirements, supply, salt content of the water, salt content of thecrude, and other factors specific to the desalting conditions, size ofthe separator, and desalted product required.

“Separator vessel” or “separator tank”, also called a separator orcoalescer, as used herein describes any number of tanks or vessels thatuse gravity and electric charge to coalesce and separate oil and wateremulsions into a clean oil and wastewater effluent. Separators areavailable from a variety of commercial and custom sources and includethe National Tank Co. (NATCO™), NRG manufacturing, Trivolt, Pall Corp.,Primenergy LLC, Hamworthy Technology & Products, and many other sources.Separators include low pressure and high pressure separators, 2 phaseseparators, electrostatic coalescence separators, AC deep-fieldelectrostatic separator/dehydrator, dual frequency separator vessels,DUAL FREQUENCY® treater (NATCO™), dual polarity combination AC/DCelectrostatic separator vessels, the DUAL POLARITY™ treater (NATCO™),Electro-Dynamic®desalter (NATCO™), 3 phase separator (gas, oil andwater), High Velocity Electrostatic Coalescing Oil/Water Separator,LUCID™ Separator (Pall Corp.), TRIVOLT™ or TRIVOLT MAX™, Vessel InternalElectrostatic Coalescer (VIEC, Hamworthy) or other available separatormanufacturers and suppliers.

“Disk stack centrifuge” as used herein describes any of numerouscommercially available separators and centrifuges that separatesubstances and solids from liquids using a high acceleration field and astack of conical disks to create a large equivalent clarification areabelow each of the disks. Stacked disk centrifuges include nozzleseparators, self-cleaning disk separators, solid-wall separators, andthe like which contain a stack of conical disks either with or withoutchambers to collect a variety of materials separated using highacceleration fields. The type of separator used depends on the mode ofoperation, type of crude oil being processed, contaminants in the crudeoil, and properties of crude oil emulsion being separated. In oneexample, a solid-wall stacked disc separator is used during batchprocessing to remove solids from the emulsion. In another example, crudeoils with high levels of solids contamination are run continuously in astacked disk nozzle separator. In the nozzle separator, solids aredischarged through nozzles fitted at the bowl periphery. Ports arespaced evenly around the bowl periphery of the centrifuge. The ports maybe fixed as in a conventional stacked disk centrifuge with fixed orificenozzles, or adjustable ports may be open partially or continuously asrequired to release solids inside the chamber. Separators with aself-cleaning bowl are able to periodically discharge the separatedsolids at full speed where a remotely operated ejection system enablesboth partial and total ejections to be triggered during productseparation without stopping or slowing the centrifugal separator.Commercial suppliers of new and used stacked disk centrifuges includeGEA Westphalia Separator (Oelde, Germany), Alfa Laval (Lund, Sweden),Mars Tech (New City, N.Y., USA), TEMA Systems (Cincinnati, Ohio, USA),Broadbent (West Yorkshire, United Kingdom), and other suppliers.

ASTM D4006 describes one method to measure water content includingsoluble water within the oil by distillation. Total water content, waterdroplet content, water droplet size, and dispersion may be calculatedusing numerous assays available in the art including visual examinationof oil color/haziness, a visual crackle test, a quantitative oil/wateranalysis, spectroscopic methods, scattering, back-scattering,absorbance, infrared (IR), ultraviolet (UV), elemental determination bylaser, quantitative FTIR analysis, and many other standard water and oilquantification techniques including spectroscopic and chemical analysis.Increasing water content in the oil or increasing oil in the water isindicative of a processing rate that exceeds the rate of oil and waterseparation in the separator. This occurs as the rag layer expands to theclean oil and/or water feed outlets causing increasing contamination ofthe separated products.

Water DSD measurements were performed using a crude oil/solvent systemin a Malvern Mastersizer 2000 instrument using a laser source in awater-saturated toluene dilution. Araujo (2008) and Kraiwattanawong(2009) provide additional guidance on the factors that influencemeasurements in Malvern Mastersizers. The cutoff diameter (d(0.1) ord(0.5)) was chosen as the geometric mean of the upper and lower valuesof the largest diameter ranges wherein droplets were detected whereeither 10 percent or 50 percent of the droplets have a smaller diameterthan the size given. Thus for a d(0.1) of 10 μm, 90 percent of the waterdroplets are larger than 10 μm and 10 percent of the water droplets areless than 10 μm. For water droplet distribution of d(0.5) of 10 μm, ½ ofthe droplets would be larger than 10 μm and ½ of the droplets would besmaller than 10 μm.

The following experiments demonstrate various embodiments of theinvention. Each example is provided by way of explanation of theinvention, one of many embodiments of the invention, and the followingexamples should not be read to limit, or define, the scope of theinvention. The objective of the experiments was to demonstrate theability of a disk stack centrifuge to resolve oil in water dispersionswith very small water drop size distributions.

Experiment 1: Small Scale MacKay River Heavy Crude Oil Process

Initial assays were conducted on a small scale to demonstrate theconcept and effectiveness of using stacked disk centrifuge to separatelarge volumes of crude oil rag layer for distillation and furtherprocessing. Approximately four drums of a MacKay River Heavy (MRH) crudeoil blend with a gravity of 19.9° API were obtained from the AthabascaTerminal in Alberta, Canada and desalted using the stacked diskcentrifuge system.

MRH was processed in a blend tank with a water/brine solution through anemulsion pump to replicate a rag layer emulsion as found in separatorrag layers. MRH was fed to the blend tank with a water/brine from thewater tank, the blended crude oil went through an emulsion pump. Anemulsion pump exit line branching to a blend tank return line and a feedline, were fed into a stacked disk centrifuge desalting system with thefeed line going through an optional steam driven heat exchanger tocontrol temperature in the separation tank and/or a stacked diskcentrifuge. The mixed oil and water emulsion was fed to the small scalestacked disk centrifuge at a constant temperature to ensure that goodrag layer separation occurred at temperatures close to commercial planttemperatures. For one or more of the runs, a GEA Westfalia Separatorstacked disk centrifuge was used to separate water and oil from anemulsified mixture. Other stacked disk centrifuges, availablecommercially, may be substituted or used in series to further separatewater from the crude oil emulsion. Two lines exited the stacked diskcentrifuge: the first waste water line goes to a waste water storagetank and/or a waste water purification system; and the second oilfeedstock goes to a storage tank and/or refinery feed for furtherprocessing. In some embodiments the waste water is fed directly into theseparator tank to maintain separator tank volume and flow rate. A returnline may be used to return any rag layer and/or higher water emulsionsobtained to the separator tank, blend tank or other point for additionalemulsion and/or centrifugation and for further separation.

In this example, approximately 200 gallons of MRH crude oil in the blendtank (plus about 30 gallons of line fill) were mixed with 22 gallons ofdeionized water through the an emulsion pump system [UNIT 12]. The 19.9°API MacKay River Heavy oil sample [37559-16-1] were blended andemulsified in the blend tank to create a uniform ‘rag layer’ emulsion.Water was added for about 8 minutes, and the blend tank mixturecontinued to roll through a ten-stage downhole high-shear centrifugalpump for an additional 10 minutes before the pump was shut down and thenormal roll pump was started (a single stage centrifugal pump). Theblend tank was cooled before, during, and after the emulsion was formedby tap water flowing through the blend tank jacket. This blendedemulsion represented a ‘rag layer’ that may be obtained from a separatortank during standard desalting operations. Temperature of the oil andthe final emulsion was about 100° F. The centrifuge was preheated withdeionized water fed through a steam heat exchanger to approximately 200°F., when feed from the blend tank was started at about 3 gpm. Nodemulsifier or other breaking chemicals were added to the emulsifiedfeed prior to centrifugation. Feed and product flow indicators gaveerratic readings throughout the test, so flow was determined by changein blend tank volume versus time. Four sets of samples at variousstages, including a feed sample (1-qt), product sample (1-qt), wateroutlet (4 oz.), chilled feed sample (2 oz) and chilled product sample (2oz) for water DSD analysis were taken during the approximately 1 hour 30minutes of run time. Feed was held at an essentially constant pressureand rate, and four feed temperatures were targeted for testing as shownin Table 1, approximately 190° F. (187-194° F.), approximately 200° F.(198-230° F.), approximately 180° F. (170-205° F.), approximately 210°F. (197.5-213° F.), approximately 170° F. (158.5-206° F.) all coolerthan conventional desalter temperatures.

Although salt in the oil out samples appears high, the chloride numbersdo not support those results. We have seen similar discrepancies betweenchloride assays ASTM D3230 and D6470 in previous Canadian oils, and thechloride number is considered much more accurate and indicative ofdesalter performance. A chloride content of 3 wppm should correspond to1.6 PTB (assuming all NaCl) for this oil, not 5 PTB as shown in Table 1.FIG. 1A is a plot showing the D3230 results against the expected resultsbased on D6470 results. The feed emulsion appeared to be stable duringthe course of the run, chiefly by examination of the water d(0.5) of theoil in samples. D(0.5) is defined as the droplet diameter at which halfof the water volume is in larger droplets (and half is in smallerdroplets). For a normal distribution, this would be very close to thepeak of the monotonic curve of volume percent versus droplet diameter.

Four crude oil samples were desalted, two drums from the original12-drum sample and two drums blended from the 10 remaining drums. Theremaining eight blended drums and three desalted drums were stored forfuture use. Salt measured by ASTM D3230 gave an artificially high resultcompared to the chloride content measured by ASTM D6470. This was alsoobserved during other recent assays with non-conventional crude oils.

TABLE 1 MRH Summary of Temperature, water, salt, and particle size WaterSalt Cl— Water Batch Ave Low High (D4006, (D3230, (6470, (d(0.5),(Sample) Temp Temp Temp vol %) PTB) wppm) μ) Ca Mg Na Cl Oil in 193.1193 194 10.1 35.9 48.3 14.5 [17-4](1-1) Oil out 187.5 187 188 0.55 5.33.39 1.5 7.15 <0.019 3.01 3.39 [17-2] (1-2) Water out n/a n/a n/a 4.440.968 268 339 [17-5] Oil in 223.7 215 230 10 32.1 42.1 13.5 [17-9] (1-3)Oil out 202.4 198 207 0.25 4.8 2.22 1.5 7.65 <0.014 1.69 2.22 [17-7](1-4) Water out n/a n/a n/a 4.9 0.824 243 322 [17-10] Oil in 182.7 152205 10.6 30.7 41.2 15.3 [17-14] (1-5) Oil out 181.7 169 189 0.575 5.13.46 n/a 9.91 <0.017 3.09 3.46 [17-12] (1-6) Water out n/a n/a n/a 5.081.01 241 319 [17-15] Oil in 185.5 185 186 10.2 25.4 37.6 17.2 [17-19](1-7) Oil out 181.7 182 182 0.55 4.9 2.51 1.5 12.3 0.016 1.98 2.51[17-17] (1-8) Water out n/a n/a n/a 4.61 0.949 223 317 [17-20] Combinedn/a n/a n/a 0.5 7.1 7.86 2 (1-2, 1-4, 1-6 and 1-8) Oil in 209.9 207 2131.8 9.3 12.1 4 [19-2] (2-1) Oil out 197.5 195 199 0.3 5 3.35 n/a 8.85<0.011 2.59 3.35 [19-4] (2-2) Water out n/a n/a n/a 5.51 0.674 227 284[19-5] Combined n/a n/a n/a 0.3 5 3.75 2.2 [19-8] (batch 1&2) AVERAGE 198.980    190.400    205.600 8.540 26.680 36.260 12.900 OIL IN AVERAGE 158.467    155.167    160.833 0.371 4.183 2.488 1.125 9.172 0.015 2.4722.986 OIL OUT WATER n/a n/a n/a 4.908 0.885 240.4 316.2 AVERAGE

The Malvern output for incoming oil, FIG. 1B [17-3], and outgoing oil,FIG. 1C [17-2], demonstrates a bimodal distribution for the incoming oilwhere the smaller peak likely represents the droplets left in the oilduring the production process, with most of the larger peak representingadded water. This is supported by the water DSD of the oil prior toforming the emulsion, FIG. 1D. The cutoff of the smaller peak isestimated as about 4 microns, the centrifuge removed some of thedroplets present in the oil as received which shows a cutoff ofapproximately 14.1 microns. The large submicron peak in FIG. 1C islikely residual solids in the oil. Evidence of solids in the centrifugebowl after the run were consistent with the solids particle size range,approximately 10 grams of solids were recovered from the bowl after theinitial test. There was no evidence of solids sticking to the disks. Ina commercial installation, solids will be discharged from the peripheryof the bowl through open nozzles.

Water separated from the feed emulsion was collected during the last fewminutes of the run. After three minutes, 5.66 pounds of water werecollected. Assuming a density of water at 180° F. of 8.1 pounds pergallon, and the difference in water content from the last set of samplescollected (samples 1-7 and 1-8), the feed flow rate would have beenapproximately 2.4 gpm. If we assumed 3 gpm (as measured by blend tankstrapping vs time earlier in the run), one would only calculate aremoval of 7.8 vol % water from the feed instead of the 9.65 vol %actually achieved. The feed rate drop as the run progressed can beexplained by the drop in blend tank pressure, as internal pressuredecreased from 34 psig to 21 psig over the course of the run. Reliablefeed and production rates of a commercial scale unit will make theseparation more consistent.

FIG. 1E demonstrates the water DSD of combined oil out samples aftercentrifugation. Submicron peaks (<1.0 μm) were eliminated from theresults for clarity. The d(0.5) of 2.0 and the cutoff of 4.1 microns areboth slightly higher than the values reported for the oil out samplesshown above. This is likely due to conditions during the testing wheresteady state separation was not achieved, but still indicates quite goodseparation on average. The only oil that did not end up in Tank 8 wasthe eight gallons left in the blend tank as well as line fill not fed tothe centrifuge during the experiment.

The oil was run back through the centrifuge to see if additional watercould be separated. Oil from the product tank was transferred back tothe blend tank and mixed with the remaining eight gallons plus linefill. Initial volume was 164 gallons at about 100° F. Table 1 shows theanalytical results for the feed (2-1) as well as a product sample (2-2)and the combined oil in the product tank.

FIG. 1F shows the water DSD of the feed and FIG. 1G shows the water DSDof the product. A good water DSD measurement was not obtained for thesecond product, sample 2-2, but did get a good one on the combinedproduct (1&2 combined). A cutoff diameter of 9.3 microns was determinedfor the combined sample while a cutoff diameter of 2.7 microns wasdetermined for all of the product samples from the first run (1-2, 1-4,1-6, & 1-8).

Three drums of desalted product from this experiment were stored forlater use. A sample of 248 lb (approximately 32 gallons) of untreatedoil recovered from the blend tank and piping was also stored.

Chloride extraction efficiency is determined from Na and Cl— contents ofthe separated waters corrected for the measured watercut (none of theimpurities were assumed to come from the deionized water), and the massconcentration was divided by the appropriate molecular weight. FIG. 1Hplots the results as Cl⁻ vs Na⁺. The line represents the ideal result ifonly NaCl were extracted from the crude oil. Note that all points arebelow this unity line indicating that salts and impurities other thanNaCl were also removed.

The simulated rag layer was successfully separated into a brine wastewater and a desalted and dewatered oil layer. The rag layer produceddewatered crude oil at a rate of ˜3 gpm, far faster than achieved with atwo-stage electrostatic desalter (data not shown). This work validatesthe concept and demonstrates the effectiveness of using stacked diskcentrifuge technology to rapidly separate large volumes of emulsifiedcrude oil rag layer for distillation and further pilot plant work.

Example 2 Pilot Scale Western Canadian Select Heavy Crude Oil Process

WCS crude oil blend had an API gravity very close to that of the MRH(20.4 API vs. 19.9 API). This report documents the successful desaltingof 1,995 gallons of WCS crude oil blend to prepare it for fractionationand further pilot plant testing. As described above, desalting wasaccomplished using a blend tank with water and crude oil emulsionsimulating a ‘rag layer’ fed to the stacked disk centrifuge system overthe course of 5 operating days without the use of chemical additives.Chloride removal averaged 70 percent, ranging from 65 percent to 80percent for the three composite product batches. Blend tank,emulsification pumps and a stacked disk centrifuge were used toeffectively and economically desalt non-conventional crude oils withoutchemical addition.

Pilot scale equipment was used to generate batches of emulsion withdeionized (DI) water and then to phase separate the water from the oil.

Emulsion Formation:

400 gallons of oil was transferred into a large volume blend tank atambient temperature. Circulation was established from the bottom of theblend tank, through an emulsion pump and back into the top of the blendtank through a roll line. At the established circulation rate (indicatedby flow through the emulsion pump and roll line), the average residencetime of the oil in the blend tank was calculated. The total amount ofwater to be added to the oil was added over a period of timecorresponding to this residence time, with the intent that the oil andwater mixture only make one trip through the emulsion pump. DI water wasadded at a calculated rate and measured by an in-line flow gaugecontrolled using the valve on the DI water discharge line. Startingvolume and target completion volumes were noted by the gauging marks ona polyethylene tank. When the correct amount of water had been added,the emulsion pump and DI water feed were shut down and blocked in. Finalvolume in the blend tank (calculated using the change in DI volume,change in crude oil volume, and tank strapping) was noted to confirmamount of water and crude oil added.

TABLE 2 Feed Batches Volume Temp Corrected Weight Batch (Gal) (° F.) APIVCF Gal. (lbs) T2 (FIG. 2) 62.2 96 0.9857 61.3 477.0 1 (FIG. 3) 396.7 970.9853 390.9 3041.2 2 (FIG. 4) 402.8 87 0.9893 398.5 3100.5 3 (FIG. 5)394.4 87 0.9893 390.2 3035.8 4 (FIG. 6) 394.0 89 0.9885 389.5 3030.3 5(FIG. 7) 345.2 91 0.9877 340.9 2652.5 TOTAL FEED 15337.3

The blend tank was allowed to go completely empty and the piping to thecentrifuge was blown clear during Batch #5. Thus the 345.2 gallons shownin Batch #5 includes an estimated 12.6 gallons from the roll pump pipingand the estimated 10.6 gallons in the feed piping. The DSD of the wateradded can generally be described as a log normal distribution with abouthalf the volume of water in droplets smaller than 25 microns, 10%smaller than 11 microns, and only 10% of the water in droplets largerthan 50 microns. FIG. 11 shows the distribution of small particles inthe blended WCS without water (starting crude oil). After emulsificationthe submicron peak contains both small particles as seen above withwater droplets making the submicron peak (<1 μm) larger than the oilemulsion peak between 10 and 100 microns (FIG. 12). Removing thesubmicron peak, displaying only the emulsion greater than 1 μm shows theemulsion is centered around ˜25 microns with 10 vol % of the droplets inthis distribution having less than 11 microns in diameter, and only 10%having greater than 50 micron diameter. The diameter below which 50 vol% of the water volume exists is approximately 25 microns (definition ofd(0.1), d(0.9), and d(0.5), respectively).

Phase Separation:

Each batch of emulsion was phase-separated using a GEA WestfaliaSeparator ODA-7 stacked disk centrifuge bowl where separation occurs ata maximum ID of 252 mm and a rotational speed of 7,850 rpm. This meansthat acceleration at the periphery of the bowl is 8,700 times that ofgravity. Separation of water droplets from the emulsion happens veryquickly as a result. Nitrogen pressure on the blend tank was used topush emulsion to the centrifuge. Flow rate of emulsion was controlledusing the nitrogen pressure valve, and temperature was controlledmanually using the blend tank jacket flow and an inline heat exchange.Temperatures were measured by the blending tank thermometer and inlinethermometers for various feeds. Flow rates were approximately 2.5 to 3.5gpm, and centrifuge feed temperatures were generally held between 160°F. and 180° F. Phase separated water flow and quality were monitoredthrough a sight glass during operation. Separated water was dischargedto the 400-gallon wastewater tank. Dehydrated oil was pumped with thestacked disk centrifuge centripetal pump to a 100-gallon vessel. Whenthe high alarm point on the oil storage vessel was reached the controlsystem automatically pumped the contents to a 500-gallon capacitystorage tank. The automatic pump was shut down when the 100-gallonvessel reached the low alarm point. This sequence continued through thecourse of a batch. When the blend tank volume reached zero (feed pipingand pumps were not drained and remained filled with emulsion), systemwas closed, and all valving was configured to prepare the next batch ofemulsion in the blend tank. The 500-gallon vessel contents weretransferred to either drums or to one or more long term storage tanksFlex hoses were used to transfer oil from the 100-gallon vessel to the500-gallon vessel during the course of running a batch, and the hoseswere disconnected when other transfers were being made. Samples ofcentrifuge feed emulsion and dehydrated product were obtained at severalpoints during each batch. Watercut was measured by the HotSpin method(as previously described) and DSD was measured using a dilute toluenedispersion of the samples in a Malvern Mastersizer 2000. Added water DSDis described above and was consistent through all samples analyzed. Thecutoff diameter of the product water DSD (that diameter above which nowater droplets were detected) varied between 2 and 6 microns, indicatingthat virtually all added water had been removed and that part of thenative water had also been removed.

The 345.2 gallons in batch #5 includes an estimated 12.6 gallons fromthe roll pump piping and the estimated 10.6 gallons from the feed pipingas the blend tank was allowed to go completely empty and the piping tothe centrifuge was blown clear.

Extractable chloride content of sample #1 feed emulsion was 27.1 wppmand the product was 8.8 wppm. Extractable chloride content of sample #4feed was 23.7 wppm and the product was 9.2 wppm. These are chlorideremovals of 71 percent and 65 percent respectively on a dry oil basis.The measurements of watercut in the products were essentially at thelower limit of what can be determined using the HotSpin method.

A total of 1,995 gallons of WCS crude oil emulsion were separated intoclean oil and brine waste water. Aliquots from feed crude oil emulsionas well as produced clean oil and waste water were sampled before duringand after stacked disk centrifugation to assess emulsion separation andcontaminant levels in the clean oil and waste water. Additionally, arepresentative aliquot from a separate supply was provided for a fullheavy crude oil assay. Six emulsion batches were made and dewateredbetween during a 1 week period. The first batch was a small batch(designated “Batch T”) used to test separation conditions to be used inthe remaining batches. 12 gallons of DI water were emulsified into 100gallons of oil. It was hoped that separation could be effected withoutheating the emulsion feed to the centrifuge. Several attempts toaccomplish this were not successful. Approximately 50 gallons of feedemulsion were used in this attempt, 30 gallons of which ended up in 100gallon vessel, and 20 gallons of which ended up in a wastewater tank.The 30 gallons in 100 gallon vessel were drummed out and put into theblend tank as part of the sixth and last batch. The desalted crude oil(FIG. 14) was similar to the blended crude initially measured exceptthat solids and water were removed from the dehydrated product.

TABLE 3 Pilot Scale Dehydration Feed Feed Product Product Cl— Water, OilWCSR Water Cl— Water Cl— removed & Grease Sample Batch API (vol %)(wppm) (vol %) (wppm) (%) (wppm) FIG. 1 T2 20.4 11.3 27.1 0.40 8.8 67.52 2 T2 10.1 0.20 2 3 T2  9.4 0.20 2 4 T2  9.6 23.7 0.60 9.2 61.1 448 2 51 18.2 11.0 0.13 3 6 1 10.6 0.10 3 7 1 10.4 0.05 6.8 3 8 1 — 0.05 3 9 1— 0.06 326 3 10 2 18.6 — 0.05 4 11 2 11.6 0.12 4 12 2 — 0.07 174 4 13 318.6 13.5 0.15 5.6 5 14 3 — 0.13 5 15 3 — 0.20 5 16 3 13.5 0.19 129 5 174 18.3 — 0.26 6 18 4 — 0.18 6 19 4 13.9 0.53 6 20 4 13.9 0.98 137 6 21 518.3 14.0 0.66 7 22 5 — 1.55 7 23 5 14.0 1.65 7 24 5 — 1.70 6.3 213 7 ByAnalytical Services (A/S) on select water samples.

In total, about 2,000 gallons of WCS was effectively desalted (average70% chloride removal in a single stage) over the course of 5 operatingdays, with 800 gallons being desalted during one of those days. Goodwater separation was seen during the conditions tested both in the smallscale and pilot scale separations. This rag layer separation method hasadvantages over existing desalting methods, because maintaining aconsistent rag layer allows increased production rate with decreasedcontaminants in the produced crude oil and waste water. Additionally,non-traditional crude oils with increased salt content, more solids, andlower APIs hinder traditional separation techniques, but can now beseparated using a separation chamber and a stacked disk centrifuge. Thisdecreases the amount of chemical treatment, heat treatment or othermodifications to the emulsion and allows clean crude oil separation athigher rates.

Example 3 Commercial Scale Heavy Crude Oil Process

In one example, a commercial scale desalting system can have a separatortank with a clean crude outlet, wastewater outlet and rag layer outlet,the rag layer outlet feeds directly to a stacked disk centrifugeoperating at a rate required to keep the rag layer height fairlyconstant preventing rag layer contamination of wastewater and oilfeedstreams. The stacked disk centrifuge can separate the oil and wateremulsion at a rate of greater than 3 gpm, sufficient to process the raglayer produced in a conventional refinery separator. If a greaterprocessing capacity is required, additional stacked disk centrifuges orlarger stacked disk centrifuges may be used to process the rag layer ata greater rate. If a higher level of separation is required,contaminants are still present in the clean crude oil, then additionalstacked disk centrifuges may be used. Separated water may be fed intonumerous water systems on the refinery including back into theseparator, into a wastewater stream, and/or purified to recycle wastewater. Clean crude oil is fed into the outgoing oil feedstream.

Using an open-nozzle centrifuge such as the Westfalia ODB-260, solidsare removed continuously at centrifugation speeds through controllednozzles along the circumference of the centrifuge. Higher levels ofwater and salt removal are achieved through consistent feed supplies andremoval of solids during stacked disk centrifugation.

A continuous commercial desalter apparatus includes an incoming mixedheavy crude oil and water/brine feedstock feeding into a commercialgrade separator with three or more outgoing streams including a crudeoil stream, a waste water stream and a rag layer stream. The rag layerstream feeds into a stacked disk centrifuge with three or more outputstreams including desalted crude oil, a wastewater and solids. Thedesalted crude oil product is sufficient for additional refining and mayfeed directly into the separator crude oil stream or other crude oilstream. The wastewater stream may be fed back into the separator aqueouslayer, as a feed for the water/brine, or into a wastewater stream, or bepurified, de-ionized or recycled. Because this process can reduce theamount of emulsion breakers or other added chemicals required, the costsof desalting are dramatically reduced. Additionally, this system allowsthe convention separator to run at a much higher rate, by maintaining afairly constant rag layer thickness water contamination of the outgoingcrude oil stream and oil contamination of the outgoing wastewater areminimized. The difficult to separate rag layer is no longer ratelimiting for the separator and the rag layer can be removed andseparated at a much higher flow rate in the stacked disk centrifuge.This system produces consistent results desalting a variety ofnon-conventional heavy crude oils and high salt crude oils. Previousmethods were unable to desalt non-conventional crudes due to low API,high viscosity, high salt content, and the rate of production would beslowed by rag layer contamination of products.

In closing, it should be noted that the discussion of any reference isnot an admission that it is prior art to the present invention,especially any reference that may have a publication date after thepriority date of this application. At the same time, each and everyclaim below is hereby incorporated into this detailed description orspecification as a additional embodiments of the present invention.

Although the systems and processes described herein have been describedin detail, it should be understood that various changes, substitutions,and alterations can be made without departing from the spirit and scopeof the invention as defined by the following claims. Those skilled inthe art may be able to study the preferred embodiments and identifyother ways to practice the invention that are not exactly as describedherein. It is the intent of the inventors that variations andequivalents of the invention are within the scope of the claims whilethe description, abstract and drawings are not to be used to limit thescope of the invention. The invention is specifically intended to be asbroad as the claims below and their equivalents.

REFERENCES

All of the references cited herein are expressly incorporated byreference. The discussion of any reference is not an admission that itis prior art to the present invention, especially any reference that mayhave a publication date after the priority date of this application.Incorporated references are listed again here for convenience:

-   1. U.S. Pat. No. 4,415,434, “Multiple stage desalting and dedusting    process,” Standard Oil, Hargreaves and Hensley (1983).-   2. U.S. Pat. No. 4,473,461, “Centrifugal drying and dedusting    process,” Standard Oil, Thacker and Miller (1984).-   3. U.S. Pat. No. 4,938,876, WO9009833, “Method for separating oil    and water emulsions,” Dr. Ernest O. Ohsol, (1990).-   4. U.S. Pat. No. 5,219,471, “Removal of metals and water-insoluble    materials from desalter emulsions,” Amoco Corp., Goyal, et al.    (1993).-   5. U.S. Pat. No. 5,738,762, “Separating oil and water from emulsions    containing toxic light ends,” Dr. Ernest O. Ohsol, (1998).-   6. U.S. Pat. No. 5,882,506, WO9925795, “Process for recovering high    quality oil from refinery waste emulsions,” UniPure Corp., Ohsol, et    al. (1999).-   7. U.S. Pat. No. 5,948,242, WO9919425, “Process for upgrading heavy    crude oil production,” UniPure Corp., Ohsol, et al. (1999).-   8. U.S. Pat. No. 7,612,117, US20070111903, US2007112079,    WO2007061722, “Separatory and emulsion breaking processes,” Gen.    Electric, Engel, et al. (2007).-   9. Araujo, et al., “Evaluation of Water Content and Average Droplet    Size in Water-in-Crude Oil Emulsions by Means of Near-Infrared    Spectroscopy,” Energy Fuels, 22:3450-8 (2008).-   10. Kraiwattanawong, et al., “Effect of Asphaltene Dispersants on    Aggregate Size Distribution and Growth,”Energy Fuels, 23:1575-82    (2009).-   11. Zaki, et al. “A Novel Process for Demulsification of    Water-in-Crude Oil Emulsions by Dense Carbon Dioxide,” Ind. Eng.    Chem. Res. 2003, 42, 6661-6672-   12. Nnanna, et al., “Emerging Technologies and Approaches to    Minimize Discharges into Lake Michigan,” Purdue University Calumet    Water Institute—Argonne National Laboratory Task force, (2008)-   13. ASTM D6470-99 Standard Test Method for Salt in Crude Oils    (Potentiometric Method)-   14. ASTM D6470-99 (2004) Standard Test Method for Salt in Crude Oils    (Potentiometric Method)-   15. ASTM D3230-09 Standard Test Method for Salts in Crude Oil    (Electrometric Method)

1. A crude oil desalter system comprising: a) an oil and waterfeedstream comprising a crude oil and water mixture; b) a separatorconnected to said feedstream wherein said separator comprises three ormore outgoing streams including an outgoing crude oil stream, anoutgoing wastewater stream and an outgoing rag layer stream; c) one ormore outgoing rag layer streams connected to a disk stack centrifugewherein said disk stack centrifuge comprises three or more outgoingstreams including an outgoing crude oil stream, an outgoing wastewaterstream and an outgoing solids rich stream; d) one or more outgoingstreams comprising a desalted crude oil; and e) one or more outgoingstreams comprising wastewater.
 2. The desalter of claim 1, wherein saidseparator is selected from the group consisting of one or more lowpressure separators, high pressure separators, 2 phase separators,electrostatic coalescence separators, AC deep-field electrostaticseparators, dual frequency separators, dual polarity combination AC/DCelectrostatic separators, 3 phase separators, high velocityelectrostatic coalescing separators, vessel internal electrostaticcoalescers, and combinations thereof.
 3. The desalter of claim 1,wherein said disk stack centrifuge is selected from the group consistingof nozzle separators, self-cleaning disk separators, solid-wallseparators, and the like which contain a stack of conical disks eitherwith or without chambers to collect a variety of materials separatedusing centrifugal forces.
 4. The desalter of claim 1, wherein saidmethod comprises heating said crude oil emulsion to a temperaturebetween approximately 140° F. and 300° F. selected from the groupconsisting of about 140° F., 150° F., 160° F., 170° F., 180° F., 190°F., 200° F., 210° F., 220° F., 230° F., 240° F., 250° F., 260° F., 270°F., 280° F., 290° F. and about 300° F. prior to separation orcentrifugation in the stacked disk centrifuge.
 5. The desalter of claim1, wherein said crude oil is selected from the group consisting ofAthabasca oil sands (crude bitumen), Orinoco oil sands (extra heavyoil), Canadian Extra Heavy Oil (CXHO), Western Canadian Select (WCS),MacKay River Heavy (MRH), oil shales, crude bitumens, extra heavy oils,oilsands, tarsands, sour crudes, and mixtures thereof.
 6. The desalterof claim 1, wherein said water is selected from the group consisting oftap water, de-ionized (DI) water, recycled water, distilled water,chilled water, heated water, ultra-purified water, clarified water, andmixtures thereof.
 7. The desalter of claim 1, wherein said crude oilemulsion comprises a particle size distribution of approximately 1 to 20μm, approximately 5 to 15 μm, approximately 9 to 14 μm, approximately 7μm, 8 μm, 9 μm, 10 μm, 11 μm, 12 μm, 13 μm, 14 μm, or approximately 15μm.
 8. A process for removing water from crude oil comprising: a)providing an oil and water feedstream comprising a crude oil and watermixture; b) feeding the oil and water feedstream to a separator withthree or more outgoing streams including an outgoing crude oil stream,an outgoing wastewater stream and an outgoing rag layer stream; c)removing said outgoing rag layer stream from said separator; d)centrifuging the rag layer in a disk stack centrifuge wherein said diskstack centrifuge comprises three or more outgoing streams including anoutgoing crude oil stream, an outgoing wastewater stream and an outgoingsolids rich stream; e) removing a desalted crude oil stream; and f)removing a wastewater stream.
 9. The desalter of claim 8, wherein saidseparator is selected from the group consisting of one or more lowpressure separators, high pressure separators, 2 phase separators,electrostatic coalescence separators, AC deep-field electrostaticseparators, dual frequency separators, dual polarity combination AC/DCelectrostatic separators, 3 phase separators, high velocityelectrostatic coalescing separators, vessel internal electrostaticcoalescers, and combinations thereof.
 10. The desalter of claim 8,wherein said disk stack centrifuge is selected from the group consistingof nozzle separators, self-cleaning disk separators, solid-wallseparators, and the like which contain a stack of conical disks eitherwith or without chambers to collect a variety of materials separatedusing centrifugal forces.
 11. The desalter of claim 8, wherein saidmethod comprises heating said crude oil emulsion to a temperaturebetween approximately 140° F. and 300° F. selected from the groupconsisting of about 140° F., 150° F., 160° F., 170° F., 180° F., 190°F., 200° F., 210° F., 220° F., 230° F., 240° F., 250° F., 260° F., 270°F., 280° F., 290° F. and about 300° F. prior to separation orcentrifugation in the stacked disk centrifuge.
 12. The desalter of claim8, wherein said crude oil is selected from the group consisting ofAthabasca oil sands (crude bitumen), Orinoco oil sands (extra heavyoil), Canadian Extra Heavy Oil (CXHO), Western Canadian Select (WCS),MacKay River Heavy (MRH), oil shales, crude bitumens, extra heavy oils,oilsands, tarsands, sour crudes, and mixtures thereof.
 13. The desalterof claim 8, wherein said water is selected from the group consisting oftap water, de-ionized (DI) water, recycled water, distilled water,chilled water, heated water, ultra-purified water, clarified water, andmixtures thereof.
 14. The desalter of claim 8, wherein said crude oilemulsion comprises a particle size distribution of approximately 1 to 20μm, approximately 5 to 15 μm, approximately 9 to 14 μm, approximately 7μm, 8 μm, 9 μm, 10 μm, 11 μm, 12 μm, 13 μm, 14 μm, or approximately 15μm.
 15. A method of reducing a crude oil emulsion rag layer comprising:a) feeding an oil and water feedstream to a separator with three or moreoutgoing streams including an outgoing crude oil stream, an outgoingwastewater stream and an outgoing rag layer stream; b) removing saidoutgoing rag layer stream from said separator; c) centrifuging the raglayer in a disk stack centrifuge wherein said disk stack centrifugecomprises three or more outgoing streams including an outgoing crude oilstream, an outgoing wastewater stream and an outgoing solids richstream; d) removing a desalted crude oil stream from said separator andsaid disk stack centrifuge; and e) removing a wastewater stream fromsaid separator and said disk stack centrifuge.
 16. The desalter of claim15, wherein said separator is selected from the group consisting of oneor more low pressure separators, high pressure separators, 2 phaseseparators, electrostatic coalescence separators, AC deep-fieldelectrostatic separators, dual frequency separators, dual polaritycombination AC/DC electrostatic separators, 3 phase separators, highvelocity electrostatic coalescing separators, vessel internalelectrostatic coalescers, and combinations thereof.
 17. The desalter ofclaim 15, wherein said disk stack centrifuge is selected from the groupconsisting of nozzle separators, self-cleaning disk separators,solid-wall separators, and the like which contain a stack of conicaldisks either with or without chambers to collect a variety of materialsseparated using centrifugal forces.
 18. The desalter of claim 15,wherein said method comprises heating said crude oil emulsion to atemperature between approximately 140° F. and 300° F. selected from thegroup consisting of about 140° F., 150° F., 160° F., 170° F., 180° F.,190° F., 200° F., 210° F., 220° F., 230° F., 240° F., 250° F., 260° F.,270° F., 280° F., 290° F. and about 300° F. prior to separation orcentrifugation in the stacked disk centrifuge.
 19. The desalter of claim15, wherein said crude oil is selected from the group consisting ofAthabasca oil sands (crude bitumen), Orinoco oil sands (extra heavyoil), Canadian Extra Heavy Oil (CXHO), Western Canadian Select (WCS),MacKay River Heavy (MRH), oil shales, crude bitumens, extra heavy oils,oilsands, tarsands, sour crudes, and mixtures thereof.
 20. The desalterof claim 15, wherein said water is selected from the group consisting oftap water, de-ionized (DI) water, recycled water, distilled water,chilled water, heated water, ultra-purified water, clarified water, andmixtures thereof.
 21. The desalter of claim 15, wherein said crude oilemulsion comprises a particle size distribution of approximately 1 to 20μm, approximately 5 to 15 μm, approximately 9 to 14 μm, approximately 7μm, 8 μm, 9 μm, 10 μm, 11 μm, 12 μm, 13 μm, 14 μm, or approximately 15μm.